Real-time data acquisition and interpretation for coiled tubing fluid injection operations

ABSTRACT

Methods for acquiring and interpreting operating parameter data during an operation to inject a work fluid into a wellbore.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention relates generally to data acquisition and interpretationof data for subterranean acidizing operations. In other aspects, theinvention relates to data acquisition and interpretation forsubterranean fracturing operations.

2. Description of the Related Art

Matrix acidizing is a stimulation process wherein acid is injected intoa wellbore to penetrate rock pores. Matrix acidizing is a method appliedfor removing formation damage from pore plugging caused by mineraldeposition. The acids, usually inorganic acids, such as fluoridic (HF)and or cloridic (HCl) acids, are pumped into the formation at or belowthe formation fracturing pressure in order to dissolve the mineralparticles by chemical reactions. The acid creates high-permeability,high productivity flow channels called wormholes and bypasses thenear-wellbore damage. The operation time depends on such parameters asthe length of the wellbore, the rock type, severity of the damage, acidpumping rate, downhole conditions and other factors.

Matrix acidizing is also useful for stimulating both sandstone andcarbonate reservoirs. Matrix acidizing efficiency in removing theformation damage is strongly dependent on the temperature at which theacidizing occurs and weakly dependent upon the corresponding pressure.The acid temperature in the formation depends on the convective heattransfer as the acid flows through the formation and on the reactionheat transfer due to the acid-mineral reaction.

Convective heat transfer is the main mechanism for temperature changeduring acid flow through wormholes. The acid temperature in thewormholes may vary by as much as 10-20° C. (18-36° F.), or more,depending on the initial temperature difference between wellbore and theformation. The acid temperature at the end of the wormholes, about 1-10m (3.3-33 feet) from the wellbore, may increase, for example, by 1°-5°C. (1.8°-8° F.) above the formation temperature at those locations,depending on the injected acid volume.

Along a wormhole, the temperature changes over time as illustrated byFIG. 4. Initially, the temperature near the wellbore is the acidtemperature inside the well (T_(w) at t=0). The rest of the wormhole,which may be partially or totally undeveloped, is assumed to be at theformation or reservoir temperature (T_(r) at t=0), which is greater thanthe wellbore temperature. As time progresses and acid is injectedthrough the wormhole, at small radial distances near the wellbore (up toabout 1 m (3.3 feet)), the acid temperature decreases from T_(r) toT_(w) with time at a rate depending upon the temperature drop of thefluid flowing from the wellbore. In other words, in the near wellregion, the temperature behavior depends only on the convection heattransfer due to the acid flow through the wormhole.

A diversion technique is important to success of matrix acidizing. In adiversion technique, diverter fluid is pumped into the wellbore prior toinjection of acid. Optimum acid placement is also important. Stimulationefficiency depends to a great deal upon temperature. Temperature willaccelerate or decelerate the chemical reactions and, thus, impact theacid volumes and flow rates required for an optimal treatment.

Prior art techniques for obtaining temperature data during acidizinghave sought to provide such data in “real time.” In most cases, adistributed temperature sensing (“DTS”) fiber is inserted into coiledtubing which is then run into the wellbore. A DTS fiber is an opticfiber having sensors along its length. The acid is bullheaded, and theDTS-enabled coiled tubing is left in place within the wellbore forhours, and temperature traces along the entire stimulated interval areacquired and interpreted at surface. Although this method is marketed asbeing “real time” in the industry, it has two major disadvantages whichhinder its effectiveness. First, the fiber is located inside the coiledtubing and does not have direct contact with the acid. Thus, itsreadings depend upon the heat transfer from the annulus acid through thecoiled tubing wall, to the DTS fiber. Second, this is not actually areal time technique, since long periods of time, usually hours, arereported for acquiring time-dependent temperature traces. Indeed, afterthe acid is bullheaded, the DTS software could evaluate the temperatureprofile and recommend more stimulation needed in certain zones. Then anew diversion/acidizing treatment would have to be executed in order toinject more acid into the targeted zone(s).

In some instances, a DTS fiber is secured to the radial exterior of thecompletion. In these cases, the DTS fiber installation is permanent. Butthe arrangement is typically very costly to maintain and prone tofailure. Additionally, it cannot be used in an open hole well that hasnot been completed.

In fracturing operations, a fracturing fluid, usually containingproppant, is injected into a wellbore at selected locations. At present,there is no reliable method for determining the flow rates for injectedfracturing fluid at locations within the wellbore in real time.

SUMMARY OF THE INVENTION

The present invention relates to systems and methods for acquiring datain real time during operations wherein a work fluid is injected intoportions of a wellbore and interpreting acquired data during or afterthe downhole operation in order to optimize injection. Exemplaryoperations of matrix acidizing and hydraulic fracturing are described.Methods in accordance with the present invention preferably use singlepoint sensors to acquire temperature and pressure data without requiringthe sensors to remain in a stationary position. In accordance withdescribed methods, fluid flow rates are determined using detectedpressure and temperature data. Mass, momentum and energy equations areused to determine the flow rates. In addition, the methods of thepresent invention allow calculation of reaction heat produced byinjection of the work fluid. In particular, embodiments, the wellbore isdivided into discrete zones and the equations are solved for each zone.Calculated temperatures are compared to measured temperatures.Calculated results for coefficients of friction closely approximateactual measured values.

In accordance with a first preferred embodiment of the invention, anacidizing arrangement is provided for acidizing a formation and includesa flow-through bottom hole assembly (BHA) which allows acid from surfaceto be distributed into the wellbore. An array of temperature andpressure sensors is carried by the BHA. Also in preferred embodiments,the BHA is run into the wellbore on coiled tubing. Further, temperatureand pressure data can be transmitted from the BHA to surface viaTelecoil or other cable arrangement. In contrast to many DTS systemswhich position a sensing fiber inside of a coiled tubing string, sensorsof the present invention are preferably in direct contact with annularfluid.

In accordance with aspects of the invention, a section of the wellboreto be acidized is divided into discrete zones for flow simulationmethods. The acidizing bottom hole assembly is then run into thewellbore until it reaches an acidizing location. During run-in, thegeothermal temperature, reservoir/annulus pressure, and coiled tubingheat transfer coefficient are measured or calculated at or for each zonewithin the wellbore section. Following run in, a diverter fluid may beflowed through the bottom hole assembly to help isolate the injectionarea. A predetermined amount of acid is then injected into the wellboreand formation while the bottom hole assembly remains in place at theacidizing location.

After acid injection at the acidizing location is stopped, the bottomhole assembly is withdrawn from the wellbore. During withdrawal,temperature and pressure are again measured at locations along thewellbore.

Temperature and pressure data is acquired within each of the discretezones of the wellbore. A mathematic model is constructed as mass,momentum and energy equations are then solved for each segment using thetemperature and pressure data acquired by the sensors.

The flow rates of acid being injected into the formation along theinjection zone are determined. The flow rates can be displayed in realtime by the controller. If desired, an acidizing profile can bedeveloped which is then compared to a planned acidizing profile.

In a second described embodiment, coiled tubing-based sensorarrangements are used to monitor operational parameters such astemperature and pressure during wellbore fracturing operations. Adescribed fracturing arrangement includes a work string and a fracturingbottom hole assembly through which fracturing fluid and proppant can beinjected. As the fracturing arrangement is run into the wellbore, singlepoint sensors, preferably located on the fracturing bottom holeassembly, detect pressure and temperature at locations along thewellbore. Once the fracturing bottom hole assembly is located proximatea location within the wellbore wherein it is desired to injectfracturing fluid, movement of the fracturing arrangement is stopped.Thereafter, fracturing fluid with proppant is injected into thewellbore. The fracturing arrangement is then withdrawn from the wellboreand, as it is withdrawn, pressure and temperature is again detected atlocations along the wellbore. Fluid flow rates are determined at eachselected location along the wellbore. Users can therefore determinewhere the fracturing treatment is actually going.

The systems and methods of the present invention also have applicationto multistage stimulation treatments wherein both acidizing andhydraulic fracturing are conducted in separate stages, A firststimulation operation, i.e., acidizing, is conducted as temperature andpressure are monitored during run in and removal of the work string fromthe wellbore. A second stimulation operation, i.e., hydraulicfracturing, is conducted as temperature and pressure are monitoredduring run in and removal. As each of these first and second stimulationoperations are conducted, as described above, fluid flow rates arecalculated and modeled.

BRIEF DESCRIPTION OF THE DRAWINGS

For a thorough understanding of the present invention, reference is madeto the following detailed description of the preferred embodiments,taken in conjunction with the accompanying drawings, wherein likereference numerals designate like or similar elements throughout theseveral figures of the drawings and wherein:

FIG. 1 is a side, cross-sectional view of an exemplary wellbore having atool string therein for conducting matrix acidizing stimulation andmonitoring in accordance with the present invention.

FIG. 2 is an enlarged side, cross-sectional view of an exemplary bottomhole assembly which incorporates a plurality of sensors in accordancewith the present invention.

FIG. 3 is an axial cross-section taken along lines 3-3 in FIG. 2.

FIG. 4 is a schematic cross-sectional drawing depicting the bottom holeassembly located proximate a location within a formation wherein it isdesired to detect matrix acidizing parameters at a first time.

FIG. 5 is a schematic cross-sectional drawing depicting the bottom holeassembly located proximate a location within a formation wherein it isdesired to detect matrix acidizing parameters at a subsequent secondtime.

FIG. 6 is a graphical representation of a section of coiled tubing andannulus.

FIG. 7 is a graph illustrating discretizing of the coiled tubing,annulus and formation.

FIG. 8 is a graph illustrating formation temperature evolution in timeat a fixed location during acid injection.

FIG. 9 is a graph illustrating formation temperature evolution in timeat a fixed location after acid injection has stopped.

FIG. 10 is a side, cross-sectional view of wellbore with a hydraulicfracturing arrangement being run in and having sensors sets to measurepressure and temperature.

FIG. 11 is a side, cross-sectional view of the hydraulic fracturingarrangement shown in FIG. 10 now with fracturing fluid being injected.

FIG. 12 is a side, cross-sectional view of the hydraulic fracturingarrangement shown in FIGS. 10-11 now with the fracturing arrangementbeing moved following injection.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 illustrates an exemplary wellbore 10 which has been drilled fromthe surface 12 down through the earth 14 to a hydrocarbon-bearingformation 16 within which it is desired to conduct matrix acidizing. Asis known, the injection of acid will cause the formation and/orlengthening and enlargement of wormholes in the surrounding formation16, thereby increasing access to hydrocarbon fluid within the formation16. A tool string 18 has been run into the wellbore 10 from the surface12 and carries a bottom hole assembly 20 in the form of a matrixacidizing tool. The bottom hole assembly 20 tool is preferably a metalcylinder having temperature and pressure sensors on its outer surfaceand connected for signal transmission to the surface, as will bedescribed. In a currently preferred embodiment, the tool string 18 ismade up of coiled tubing, of a type known in the art, which can beinjected into the wellbore 10. An annulus 22 is formed radially betweenthe tool string 18/bottom hole assembly 20 and the inner wall of thewellbore 10. It is noted that, while FIG. 1 depicts a vertical wellbore10, this is exemplary only. In fact, the systems and methods of thepresent invention are applicable to wellbore that are deviated, inclinedor even horizontal.

FIGS. 2 and 3 illustrate an exemplary bottom hole assembly 20 in greaterdetail. The exemplary bottom hole assembly 20 includes a generallycylindrical tool body 26 which defines a central axial passage 28 alongits length. A nozzle 30 is formed on the distal end of the tool body 26to allow acid injected down the tool string 18 to enter the formation16. It should be noted that the figures depict a simplified tool havingonly a single nozzle 30. In practice, the bottom hole assembly 20 mighthave multiple nozzles or openings that allow acid to be dispersed inmultiple locations and in multiple directions.

Radial passages 32 are drilled through the tool body 26 from the centralaxial passage 28 to the radial exterior of the tool body 26. A sensorarray 33 is provided proximate the lower end of the tool string 18 andpreferably upon the tool body 26 of the bottom hole assembly 20. Thesensor array 33 includes multiple sensors 34 which are divided into twosets of sensors 34 a, 34 b. The first set of sensors 34 a is axiallyseparated from the second set of sensors 34 b along the length of thetool body 26 by a length (“x”) (see FIG. 2). Each sensor 34 ispreferably located at the radially outermost portion of each passage 32.In particularly preferred embodiments, the sensors 34 are transducersthat are capable of detecting temperature and generating a signalindicative of the detected temperature. In alternative embodiments, oneor more of the sensors 34 are capable of detecting pressure. It iscurrently preferred that sensors 34 be spaced angularly about thecircumference of the tool body 22 in order to obtain sensed parametersfrom multiple radial directions around the tool body 22. In the depictedembodiment, the sensors 34 are located approximately 90 degrees apartfrom one another about the circumference of the tool body 22. In thedepicted embodiment, there are eight sensors 34. However, there may bemore or fewer than eight, as desired.

Electrical cables 36 extend from the sensors 34 to a conduit 38 that isdisposed within the central passage 40 of the tool string 18. In aparticularly preferred embodiment, the conduit 38 comprises a conductorknown in the industry as tubewire, which can be disposed within thecoiled tubing to provide a Telecoil conductive system for data/power.The term “tubewire”, as used herein, refers to a tube which may or maynot encapsulate a conductor or other communication means, such as, forexample, the tubewire manufactured by Canada Tech Corporation ofCalgary, Canada. In the alternative, the tubewire may encapsulate one ormore fiber optic cables which are used to conduct signals generated bysensors 34 that are in the form of fiber optic sensors. The tubewire mayconsist of multiple tubes and may be concentric or may be coated on theoutside with plastic or rubber. In alternative embodiments, the conduit38 may be a fiber optic cable. In further alternative embodiments, theconduit 38 may comprise a wireless communication link.

The conduit 38 extends to surface-based signal processing equipment atthe surface 12. FIG. 1 illustrates exemplary surface-based equipment towhich the conduit 38 might be routed. The conduit 38 is operablyinterconnected with a signal processor 40 of known type that can analyzeand in some cases, record and/or display representations of the sensedtemperature and/or pressure parameters. Suitable signal processingsoftware, of a type known in the art can be used to process, recordand/or display signals received from the sensors 34. In the instancewhere the conduit 38 encases optic fibers rather than electricalconductors, the surface-based signal processor 40 includes a fiber opticsignal processor. A typical fiber optic signal processor would includean optical time-domain reflectometer (OTDR) which is capable oftransmitting optical pulses into the fibers and analyzing the light thatis returned, reflected or scattered therein. Changes in an index ofrefraction in the optic fiber can define scatter or reflection points.The signal processor 40 can include signal processing software forgenerating a signal or data representative of the measured conditions.

In certain embodiments, a memory module could be operably associatedwith the bottom hole assembly 20 to store detected data. FIG. 2 depictsa memory module 37 which is operably associated with the conduit 38 andbottom hole assembly 20 to receive and store detected operationalparameter data. The stored data can be retrieved once the bottom holeassembly 20 is removed from the wellbore 10.

In conjunction with the processing equipment 40, the first set ofsensors 34 a is operable to detect at least one matrix acidizingoperational parameter at a first time while the second set of sensors 34b is operable to detect the same at least one matrix acidizingoperational parameter at a second time that is after the first time. Thedifference between the first and second time is based upon the rate ofmovement of the sensor array 33 within the formation 16 relative to aparticular point of interest. FIGS. 4 and 5 illustrate a bottom holeassembly 20 being moved within the wellbore 10 past a point 50 withinthe formation 16 at which it is desired to detect at least one matrixacidizing operational parameter. In FIG. 4, the first set of sensors 34a is located proximate the point 50. In this position, the sensors 34 adetect a matrix acidizing operational parameter at the point 50.Thereafter, the tool string 18 is pulled upwardly in the direction ofarrow 52 until the bottom hole assembly 20 is in the position shown inFIG. 5. FIG. 5 shows the second set of sensors 34 b located proximatethe point 50. In this position, the second set of sensors 34 b willdetect the same matrix acidizing operational parameter(s) as the firstset of sensors 34 a. The first set of sensors 34 a detects theparameter(s) at a first time (t1) while the second set of sensors 34 bdetect the parameter(s) at a second time (t2). The rate of movement ofthe tool string 18 and bottom hole assembly 20 in direction 52 should becoordinated with the timing of detection of the operational parameter(s)by the two sets of sensors 34 a, 34 b. This coordination can beconducted, for example, by the processing equipment 40 is such equipment40 is provided with control over the rate of movement. The processingequipment 40 will compare the operational parameters(s) detected by thefirst set of sensors 34 a to the operational parameters(s) detected bythe second set of sensors 34 b. Thus, it can be determined whether theoperational parameter is increasing, decreasing or neither. This mannerof measuring operational parameters can be repeated for multiple pointsor locations 50 along the formation interval 17. Although only a singlelocation 50 is shown in FIGS. 4 and 5, it will be understood by those ofskill in the art that there may be a large number of such points withinthe formation interval 17. Additionally, more than two sets of sensorsmight be employed to provide further detail about the measuredoperational parameter.

The use of single point sensors 34 a, 34 b with the bottom hole assembly20 allows for real-time temperature and pressure data acquisition andinterpretation as a matrix acidizing operation is performed. The methodsof operation are primarily designed for use in open-hole wells, butmight also be used with cased holes. The open hole section of thewellbore interval 17 that is to be acidized is divided into zonesdepending upon the reservoir properties and production target. Exemplarydiscrete zones 54 are depicted in FIG. 1. Zones 54 may have the samelength or be of varying lengths. Dividing the wellbore interval 17 intozones, or segments, 54 allows the tubing 18, annulus 22 and surroundingformation 16 to be treated as discrete segments for mathematicalmodeling. FIG. 6 illustrates an exemplary single zone 54 with segmentsshown of the tubing 18, annulus 22 and surrounding formation 16. In FIG.6, r_(t) and r_(a) are the tubing 18 and annulus 22 radii, respectively.These values are known. The pumping velocity or rate, v_(t) is alsoknown. A mathematical model is constructed with a system of 3N+3conservation equations (i.e., mass, momentum and energy), and 3N+3variables (i.e., flow rate, temperature, pressure) where N+1 is thenumber of tubing segments. Downhole temperature modeling for coiledtubing operations using such conservation equations is described inLivescu et al., SPE Paper 168299, “Analytical Downhole Temperature Modelfor Coiled Tubing Operations,” (2014) which is hereby incorporated byreference in its entirety. As the bottom hole assembly 20 is moved alongthe zones 54, p_(t), p_(a), T_(t) and T_(a) are measured. Then, themathematical model provides v_(a) and v_(f) along the segments.Alternatively, the bottom hole assembly 20 may be moved after pumpingacid along several zones 54. Right after stopping pumping of acid, theannulus 22 temperature and tubing 18 temperature are measured along thatinterval and then the mathematical model is used to convert these datainto acid velocities/rates. It is important to record the annuluspressure and temperature before the warm-up period (i.e., duringrun-in), and this is a significant difference between methods inaccordance with the present invention and DTS system methods. Becausethe sensors 34 a, 34 b are recording single point pressure andtemperature data, there is no need to wait for the reaction heat (due toacid dissolving rock) to return through conduction to the wellbore 10.Instead, we assume that the annulus temperature is changing as acid goesinto formation. These changes happen as long as acid is pumped. Afteracid pumping is stopped, annulus temperature slowly warms back up togeothermal temperature.

After discretizing the well into zones 54, including tubing 18, annulus22 and formation 16, into discrete zones 54, the fluid and flowproperties are averaged for all of the zones 54. Regarding the wellzones 54, for phase p, the density ρ_(p), the viscosity μ_(p), theholdup α_(p), the mixture velocity v_(m), the pressure p, and thetemperature T are averaged for each zone 54. Thermodynamic equilibriumis assumed between phases such that all phases have similar pressure andtemperature.

According to an exemplary method of operation, the tool string 18 andbottom hole assembly 20 are disposed into the wellbore 10 and advanceduntil the bottom hole assembly 20 is proximate the formation 16 intowhich it is desired to perform matrix acidizing. During run into hole,the geothermal temperature, reservoir, annulus pressure, coiled tubingheat transfer coefficient and other properties can be measured orcalculated at each location 50 along the well injection interval 17.Acid is then injected into the desired location within the interval 17by pumping acid down the tool string 18 which will then flow through thenozzle 30 of the bottom hole assembly 20 and into the wormholes 24 ofthe formation 16.

Prior to acidizing, temperature and/or pressure is detected by thesensors 34 and provided to the processing equipment 40 at surface 12.During acidizing, the bottom hole assembly 20 is not moved from onelocation to another within the formation interval 17.

After the acid injection is stopped at time (t_(s)), the work string 18is pulled out of the hole, preferably at a constant speed that can becalculated depending on the time difference (t_(f)−t_(s)) and the lengthof the stimulated zone along the well. Thus, the time t_(f) may be thetime that the matrix acidizing bottom hole assembly 20 has traveled theentire well interval of interest. The number of sensors 34 will bedependent on the accuracy of the data acquisition. For instance, asingle temperature sensor may not be sufficient for temperature dropdata interpretation, as any temperature difference recorded might be dueto either axial flow (flow inside the annulus 22) or radial flow (flowbetween the wellbore 10 and a wormhole 24). However, multiple sensors 34could accurately identify of a recorded temperature variation is due toaxial flow or radial flow. At least two temperature sensors 34 should beinstalled sufficiently far away from each other such that they capturetemperature differences due to radial acid flow. In particularembodiments, the minimum distance between two temperature sensors 34 isgreater than the radial diameter of the wormholes. Thus, it is preferredthat the sensors 34 are spaced apart from each other on the tool body 22by a distance that is greater than the diameter of the wormholes 24.Theoretical calculations show that the minimum distance between twotemperature sensors 34 should be between 4 and 20 meters (13-66 feet),depending upon the reservoir properties (porosity, permeability,wormhole size and shape, geothermal gradient, thermal conductivity,etc.) and well details (shape, dimensions, completion type, etc.). Themethod could be refined by adding temperature sensors between the twoend sensors. Adding more temperature sensors in between increases theaccuracy of temperature variation measurement. In addition to thetemperature sensors, other sensor types could be used. For instance,pressure sensors could also be installed. Both temperature and pressuremeasurements are useful in accurately evaluating the matrix acidizingperformance when they are coupled with a mathematical model that solvesthe classical energy flow equation inside the well:

${{\frac{\partial}{\partial t}\left\lbrack {\rho\left( {u + {\frac{1}{2}v^{2}}} \right)} \right\rbrack} + {\frac{\partial}{\partial z}\left\lbrack {\rho\;{v\left( {h + {\frac{1}{2}v^{2}}} \right)}} \right\rbrack}} = Q$where ρ is acid density, t and z are time and the curvilinearcoordinated along the well path, v is acid velocity, u=c_(p) (T−T_(ref))and h=u+p/ρ are the specific internal energy and enthalpy, respectively,c_(p) is the specific heat defined at reference temperature T_(ref), andT and p are acid temperature and pressure. Note also that Q is the termthat includes all other heat exchange effects, such as heat loss due toacid flowing into/from formation.

As the bottom hole assembly 20 is pulled out of the wellbore 10,temperature and pressure data is acquired along the injection zoneformation interval 17. Using this data as input in the mathematicalmodel, the acid flow rate into the formation is calculated along theformation interval 17 by the processing equipment 40. The calculatedflow rate is used by the processing equipment 40, or by a user, toevaluate acidizing performance and decide in real time how the acidizingjob could be optimized. For example, if the acid did not create enoughwormholes or if there is a thief zone, the bottom hole assembly 20 couldbe moved back to a particular location 50 within the formation interval17 for additional acid injection at that location 50.

Mathematical modeling is preferably performed by the processingequipment 40 to determine acid fluid flow rates and reaction heat (i.e.,heat created by reaction between the acid and formation). The values aredetermined using modeling which considers the formation interval 17 asdivided into discrete zones 54. This modeling permits each zone 54 to betreated as one-dimensional elements (in the axial direction) for bothtubing 18 and annulus 22 flows and radial flow for the formation 16. Theradial flow between tubing 18 and annulus 22 is accounted for throughnozzle flow pressure drop relationships. The heat transfer betweentubing 18, annulus 22 and formation 16 are accounted for via unifiedheat transfer coefficients which, for example, take into account thethermal properties of the media between tubing 18 and annulus 22 andbetween annulus 22 and formation 16, respectively. Other heat transferrelationships should be readily implemented. The reaction heat isimplemented in the energy equation for formation 16. The flow isconsidered to be homogeneous, i.e., all phases of flow with the samevelocity (slip effects are ignored here for the purpose of simplicity;addition of mechanistic models or a drift-flux model would add an extradegree of complexity, but they could be implemented as well).

The wellbore formation interval 17 is presented as a one-dimensionaltwo-row model, as illustrated in FIG. 7. In the depicted instance, acoiled tubing section has been discretized into N+1 segments, numberedfrom 0 to N. Additionally, the annular space is discretized in N+1segments of similar length. The nearby formation is discretized into N=1cells. For each segment/cell, the physical properties are averaged inthe center. Thus, each coiled tubing segment is defined by the fluidvelocity (v_(t)), fluid pressure (p_(t)) and temperature (T_(t)). Eachannular segment is defined by the fluid velocity (v_(a)), fluid pressure(p_(a)) and temperature (T_(a)). Each formation cell is defined by fluidvelocity (v_(f)), fluid pressure (p_(f)) and temperature (T_(f)).

FIG. 8 illustrates the variation of formation temperature in time, asacid is injected into the formation 16. The x axis represents thedistance away from the wellbore 10 (r=0 corresponds to the wellborewall, i.e., where the acid leaves the annulus 22 and flows into theformation 16). The y axis is temperature. Initially, before the acid isinjected into the formation 16, the formation temperature is the sameeverywhere, T_(f). As acid is injected into the formation 16, theannulus temperature starts decreasing. At the end of the injecting time,t_(inj), the annulus temperature reached the minimum value T_(min).During acid injection, the formation temperature increases from theannulus temperature at r=0 to the formation temperature T_(f), away fromthe wellbore 10 where no acid flows. At the acid front, there is areaction between the acid and the formation rock which releases reactionheat. As a result, the formation temperature increases from the annulustemperature to a maximum (where the acid front is), and then decreasesto T_(f). The transition bumps 62, 64 correspond to temperatureincreases due to the reaction heat at the acid front travelling into theformation 16.

FIG. 9 illustrates formation temperature evolution over time at a fixedannulus location after acid injection has ended. The annulus temperatureis shown to increase from the minimum value at the end of injection tothe geothermal temperature (t_(final)) after a sufficiently long time.T_(final) from FIG. 9 is the same as T_(f) (t=0) from FIG. 8. Theappearance of formation temperature curves in FIGS. 8 and 9 is differentas the heat transfer mechanisms are different: during acidizing in FIG.8, heat is dissipated mostly by convection (and reaction at the acidfront) while during the warm-up in FIG. 9, heat is generated byconduction.

As partially illustrated by FIGS. 8 and 9, an exemplary method ofoperation for obtaining real time pressure and temperature data includesthe following steps. First, the tool string 18 and bottom hole assembly20 are run into the wellbore 10 to a desired location within theformation interval 17 without injecting acid. The sensors 34 a, 34 bobtain the geothermal temperature and the z-dependent heat transfercoefficient between the tubing and annulus. The heat-transfercoefficient is pre-calculated based upon the materials making up thework string/coiled tubing 18, well wall and the formation 16. This stepis assumed to have no flow in both the work string/tubing 18 and annulus22. Next, acid is injected through the bottom hole assembly 20 and intothe annulus 22. From there, some of the acid will flow radially out intothe formation 16 and the rest of it will flow back up through theannulus 22 toward surface. After a certain distance from the bottom holeassembly 20, all acid will flow into the formation 16. When injectingacid, with the bottom hole assembly 20 unmoved, the temperature oflocations in the formation 16 where acid is flowing into will decreasewith time. Eventually, it will reach a minimum value that depends uponthe injection time. If the injection time is long enough, the minimumtemperature will be close to the acid temperature at surface. The acidwill flow into the formation 16 and react with rock within the formation16, generating reaction heat. This reaction heat will produce anincrease of temperature next to the acid front. This temperatureincrease cannot be measured by the BHA sensors because the acid front istravelling away from the wellbore 10, as FIG. 8 reflects. After the acidinjection is stopped, the formation temperature begins increasing backdue to the difference between geothermal temperature and the annulustemperature, as illustrated in FIG. 9. Should a greater amount of acidflow into formation 16 at a particular location, the acid front willtravel further, and it will take longer for the annulus 22 temperatureto increase to the geothermal temperature.

After the acid injection is stopped, the bottom hole assembly 20 ismoved along the formation interval 17 as annulus temperature andpressure data are acquired. Knowing the time and location 50 for thedata collected, the difference between the current temperature andgeothermal temperatures as well as the difference between the currenttemperature, the initial temperature and pressure values are used tocalculate the radial flow into formation. The bottom hole assembly 20preferably has two (or more) single-point temperature and pressuresensors 34 a, 34 b. As the bottom hole assembly 20 is pulled out of thewellbore 10 after acid injection is stopped, the data from the sensors34 a, 34 b are acquired as follows: for the same location 50 atdifferent times, different readings are taken at several times (wheneach sensor set 34 a, 34 b passes in front of the location 50). Thus,temperature and pressure changes in time can be measured for differentlocations 50 at the same time. The readings at different locations willbe varied if, for example, sensor sets 34 a, 34 b pass in front of athief zone or a wormhole which would have a lower temperature than itssurrounding locations.

FIGS. 10-12 illustrate an exemplary wellbore 100 which has been drilledthrough the earth to a hydrocarbon-bearing formation 102. The wellbore100 is lined with casing 104. Perforations 106 extend through the casing104 and into the surrounding formation 102. Although only a single setof perforations 106 is shown in FIGS. 10-12, it should be understoodthat this is illustrative and that there is typically more than one setof perforations 106 present.

A hydraulic fracturing arrangement 108 is shown disposed within thewellbore 100 and includes a hydraulic fracturing work string 110. Inpreferred embodiments, the hydraulic fracturing work string 110 iscoiled tubing. A fracturing bottom hole assembly 112 is affixed to thelower end of the hydraulic fracturing work string 110. The fracturingbottom hole assembly 112 has openings 114 through which fracturing fluidcontaining proppant can be flowed.

Single point sensor sets 116 a, 116 b are located on the exteriorsurface of the fracturing bottom hole assembly 112. The sensor sets 116a, 116 b may be constructed and operate in the same manner as the sensorsets 34 a, 34 b described previously. The sensor sets 116 a, 116 b areoperably interconnected with a conduit 118 that is disposed within thecentral passage 120 of the work string 110. In a particularly preferredembodiment, the conduit 118 comprises tubewire. Although not shown inFIGS. 10-12, those of skill in the art will understand that there willbe processing equipment at surface similar to the processing equipment40 described earlier and which is capable of receiving data from thesensors 116 a, 116 b via the conduit 118 and performing mass, momentumand energy equations calculations. In accordance with preferredembodiments of the invention, an interval of the wellbore 100 is dividedinto discrete zones, as described previously with respect to wellbore10, and the method of mathematical modeling is similar.

In operation, the hydraulic fracturing arrangement 108 is run into thewellbore 100, in the direction indicated by arrow 122 in FIG. 10, untilthe fracturing bottom hole assembly 112 is proximate the perforations106. During the run-in, sensors 116 a, 116 b will sense temperature andpressure at locations along the wellbore 100. Once the fracturing bottomhole assembly 112 is located proximate the perforations 106, movement ofthe hydraulic fracturing arrangement 108 is stopped. Packers 124, 126are preferably set against the casing 104 to help isolate the area to befractured. Work fluid 128 containing fracturing proppant 130 is injectedunder pressure toward the perforations 106 causing that portion of theformation 102 which has been perforated to fracture. Once fracturingtreatment has been completed, the packers 124, 126 are unset and thehydraulic fracturing arrangement 108 is withdrawn, as indicated by arrow128 in FIG. 12. During withdrawal, the sensors 116 a, 116 b will againsense temperature and pressure at locations along the wellbore 100.

Using the pressure and temperature data that was sensed during run inand the data sensed as the hydraulic fracturing arrangement 108 iswithdrawn, fluid flow rates are calculated at surface. The calculatedflow rates are considered to be real time flow rates of work fluid intoformation. If necessary, the fracturing operation can then be adjusted.An operator can optimize the fluid flow rate and schedule based upon thedetermined fluid flow rate. For example, if the calculated flow rates atparticular location indicates that there has not been sufficientinjection of fracturing fluid 128 and proppant 130, the fracturingbottom hole assembly 112 can be moved back to that location for furtherinjection of fracturing fluid 128 and proppant 130 according to adetermined schedule and by pumping fluid at a fluid flow rate that iscalculated to effectively inject the fracturing fluid 128.

According to additional aspects of the present invention, data isacquired and interpreted for multistage stimulation treatments whichinclude both acidizing and hydraulic fracturing operations. Inaccordance with an exemplary method, a first stimulation operation,i.e., acidizing, is conducted as temperature and pressure are monitoredduring run in and removal of the work string from the wellbore.Thereafter, a second stimulation operation, i.e., hydraulic fracturing,is conducted as temperature and pressure are monitored during run in andremoval. As each of these first and second stimulation operations areconducted, as described above, fluid flow rates are calculated andmodeled. A user can adjust and optimize each stimulation operation asneeded.

Those of skill in the art will understand that the invention providesmethods for acquiring and interpreting data for downhole operationswherein a work string is run into a wellbore in order to inject a workfluid into the wellbore. In embodiments described herein, the workstring may be an acidizing arrangement (i.e., 18, 20) or a hydraulicfracturing arrangement 108. Exemplary work fluids include acidtreatments and fracturing fluids. Described methods include the steps ofrunning the work string into the wellbore and measuring temperature andpressure wellbore parameters along a desired interval within thewellbore as the work string is run into the wellbore. The work fluid isthen injected into a desired location within the wellbore as the workstring is not moved. Thereafter, the work string is removed from thewellbore, and, as the work string is removed, pressure and temperatureis again measured along the desired interval. Mass, momentum and energyequations are used to calculate fluid flow rate from the pressure andtemperature readings for individual points along the wellbore andprovide real-time information to uses at surface. Adjustments can thenbe made in the injection operation. The calculations of flow rates fromtemperature and pressure readings during run-in, and again, duringwithdrawal, allows the determination of flow rate information whichaccounts for reaction heat (i.e., heat generated from reaction betweenwork fluid and the formation) which cannot be measured directly.

Those of skill in the art will recognize that numerous modifications andchanges may be made to the exemplary designs and embodiments describedherein and that the invention is limited only by the claims that followand any equivalents thereof.

What is claimed is:
 1. A method of acquiring and interpreting operatingparameter data during an operation to inject a work fluid into awellbore, the method comprising the steps of: running a work string intoa wellbore, the work string having a bottom hole assembly with aradially exterior surface to inject a work fluid into a portion of thewellbore and at least one sensor carried on the radial exterior surfaceof the bottom hole assembly to detect temperature and pressure atlocations along the wellbore; measuring temperature and pressure withthe at least one sensor at the locations along the wellbore during thetime the work string is run into the wellbore; injecting a work fluid ata predetermined location in the wellbore; removing the work string fromthe wellbore; measuring temperature and pressure at the locations alongthe wellbore with the at least one sensor during the time the workstring is removed from the wellbore; and determining fluid flow rateinto the formation based upon measured temperature and pressure.
 2. Themethod of claim 1 wherein the work string is coiled tubing and the workfluid comprises acid.
 3. The method of claim 1 wherein the work fluidcomprises fracturing fluid containing proppant.
 4. The method of claim 1wherein the step of determining fluid flow rate into the formationfurther comprises calculating a real-time fluid flow rate into formationbased upon measured single-point pressure and temperature data.
 5. Themethod of claim 4 wherein the real-time fluid flow rate comprises a rateof acid flow into formation from acidizing.
 6. The method of claim 4wherein the real-time fluid flow rate comprises a rate of fracturingfluid flow into formation from hydraulic fracturing.
 7. The method ofclaim 4 wherein the operation to inject a work fluid into a wellborecomprises a multistage stimulation treatment which includes acidizingand hydraulic fracturing.
 8. The method of claim 1 further comprisingthe step of optimizing fluid flow rate and schedule based upon thedetermined fluid flow rate.
 9. The method of claim 1 wherein the step ofdetermining fluid flow rate into the formation further comprises:transmitting a signal representative of measured pressure andtemperature to a signal processor which is programmed to determine fluidflow rate from measured temperature and pressure; and calculating saidfluid flow rate using said signal processor.
 10. The method of claim 9wherein the step of transmitting a signal further comprises transmittingthe signal from the bottom hole assembly to the signal processor via aconduit, the conduit being from the group consisting of: Telecoil or anoptic fiber.
 11. The method of claim 9 wherein the step of transmittinga signal further comprises transmitting the signal from the bottom holeassembly to the signal processor via a wireless communication link. 12.The method of claim 1 further comprising the step of storing measuredtemperature and pressure within a memory module.
 13. A method ofacquiring and interpreting operating parameter data during an operationto inject a work fluid into a wellbore, the method comprising the stepsof: running a work string into a wellbore, the work string having abottom hole assembly to inject a work fluid into a portion of thewellbore and at least one sensor carried on a radially exterior surfaceof the bottom hole assembly to detect temperature and pressure atlocations along the wellbore; measuring temperature and pressure at thelocations along the wellbore with the at least one sensor during thetime the work string is run into the wellbore; injecting a work fluid ata predetermined location in the wellbore; removing the work string fromthe wellbore; measuring temperature and pressure at the locations alongthe wellbore with the at least one sensor during the time the workstring is removed from the wellbore; and determining fluid flow rateinto the formation based upon measured temperature and pressure whereina real-time fluid flow rate into formation is calculated based uponmeasured single-point pressure and temperature data.
 14. The method ofclaim 13 wherein the work string is coiled tubing and the work fluidcomprises acid.
 15. The method of claim 13 wherein the work fluidcomprises fracturing fluid containing proppant.
 16. The method of claim13 wherein the operation to inject a work fluid into a wellborecomprises a multistage stimulation treatment which includes acidizingand hydraulic fracturing.
 17. The method of claim 13 wherein the step ofdetermining fluid flow rate into the formation further comprises:transmitting a signal representative of measured pressure andtemperature to a signal processor which is programmed to determine fluidflow rate from measured temperature and pressure; and calculating saidfluid flow rate using said signal processor.
 18. The method of claim 17wherein the step of transmitting a signal further comprises transmittingthe signal from the bottom hole assembly to the signal processor via aconduit, the conduit being from the group consisting of: Telecoil or anoptic fiber.
 19. The method of claim 17 wherein the step of transmittinga signal further comprises transmitting the signal from the bottom holeassembly to the signal processor via a wireless communication link.